The effect of single-phase fluid saturation on the seismic bulk modulus of a rock is well understood; however, the behavior becomes more complex when multiple fluids are present. Several fluid mixing theories have been developed (e.g., Voigt, Reuss, and Hill) and each is valid in certain situations; however, in some scenarios it is unclear which theory to select, or indeed whether any are accurate. The critical wave propagation behavior depends on the manner that fluids are spatially distributed within the rock, compared to a seismic wavelength. We apply elastic finite-difference modeling to different rock-fluid distribution scenarios and replicate behavior described by various theoretical, empirical and lab data results. Significantly, our results compare well with observations from lab experiments, yet do not rely on poroelastic or squirt-flow models whose parameters are difficult to estimate in real reservoir settings. Our elastic scattering approach is less computationally expensive than poroelastic modeling and can be more easily applied to actual reservoir rock and fluid distributions. Our results provide us with a powerful new tool to analyze and predict the effects of multiple fluids and ‘patchy’ saturation on elastic moduli and seismic velocities. They also challenge assumptions about the controlling factors on saturated bulk moduli, suggesting they are more strongly affected by the spatial fluid distribution properties and wave scattering, than by pore-scale fluid flow effects.

Ideas from the field of compressive sensing are rapidly making their way into the geophysical realm. We believe that these concepts will motivate major changes in the way that our industry acquires, processes, and images seismic data. In preparation for these changes, we have undertaken an initiative to build a consistent framework for learning, investigating, and applying compressive sensing concepts to the full range of technologies used in seismic acquisition, processing, and imaging. We refer to this framework as Compressive Seismic Imaging (CSI). The components of our CSI framework include compressive sensing theory, acquisition design, processing and imaging algorithms, and the work flows that link these components into a complete system. A key element of our CSI program is the use of field trials to expose algorithms, processes, and people to the realities of deploying new technology in our industry. Before going to the field, we use extensive computer modeling to identify CSI concepts that are either ready for deployment, or require testing in the field to advance the technology. A number of 2D and 3D field trials were undertaken by ConocoPhillips in 2011 to test compressive sensing design ideas for seismic data acquisition. To date, we have acquired test datasets for validating CSI concepts for land, marine, and ocean bottom recording configurations. The key compressive sensing concepts we have tested so far include non-uniform sampling for sources and receivers, data reconstruction, simultaneous shooting, and source encoding. Initial results from these trials show that compressive sensing concepts have the potential to significantly improve acquisition efficiency. Use of the CSI framework has allowed us to quickly focus our attention on the most relevant problems for compressive sensing technology deployment, resulting in rapid progress in our understanding.

In some areas, seismic data can exhibit the effects of strong azimuthal anisotropy (AA). One of the major causes of AA can be anomalous horizontal stress regimes, which can be modeled as horizontally transverse isotropy (HTI). The Stybarrow field, located offshore NW Australia in the Carnarvon sedimentary basin, is one such area, where strong horizontal stress conditions have been present throughout the basin’s tectonic history. We find evidence for AA in repeat 3D seismic data acquired at two separate azimuths over the Stybarrow field. AA is observed in amplitude versus offset (AVO) reflection amplitude difference maps and cross plots, and is consistent with dipole shear logs and borehole breakout data in the area. We model azimuthal AVO responses using Ruger’s HTI AVO equation, using the anisotropy parameters derived from dipole shear logs, and compare the results with AVO data from the two 3D seismic surveys. Certain fault blocks (but not all) exhibit the same AAVO trend in the seismic data as those modeled from log data, consistent with a stress-induced HTI anisotropic model interpretation.

The region immediately south of West Timor, offshore Indonesia, has been largely underexplored, with only one well drilled onshore in the West Timor Block operated by eni, and no wells drilled offshore. The area is located along the Outer Banda Arc, a geologically complex, non-volcanic semi-circular belt where the Australian and Asian Plates obliquely collide. The main reservoir target is the clastic Plover formation. Imaging and resolution of the Top Jurassic horizon and the overlying accretionary section is the primary geophysical objective for prospect generation and poses a formidable challenge to marine seismic acquisition and processing.

The seismic exploration history dates back to a legacy 2D survey in 1991. In 2009, a regional 2D survey using towed streamer dual-sensor broadband technology yielded significantly improved continuity of events beneath the accretionary section. Encouraged by these results, in 2010 eni acquired a pilot study of 2D lines and subsequently a 3D survey using the same broadband acquisition technology.

Broadband marine seismic via dual-sensor streamer resulted in improved resolution of the overburden and greater penetration at the target level. These benefits are a direct consequence of eliminating the receiver ghost. Ghost-free data is rich in both low and high frequencies, has improved signal to noise ratio, and is easier to interpret.

A second important contribution comes from utilizing a unique implementation of Beam Depth Migration to correctly image the complex overburden and underlying target structure. Unique aspects of this implementation include near-vertical steep dip imaging, residual multiple attenuation in the depth domain, and the ability to detect and correctly position weak signal. These features play an important role in imaging both the accretionary prism and the target structure.

The combination of the broadband dual-sensor acquisition and the Beam migration imaging provided significant uplift in the understanding and interpretability of the seismic data promoting the development of a new exploration play in the region.

Uncertainties in marine controlled source electromagnetic (CSEM) data consist of two independent parts: measurement noise and position uncertainties. Measurement noise can be readily determined using stacking statistics in the Fourier domain. The uncertainties due to errors in position can be estimated using perturbation analysis given estimates of the uncertainties in transmitter-receiver geometries. However, the various geometric parameters are not independent (e.g. change in antenna dip affects antenna altitude, etc.) so how uncertainties derived from perturbation analysis can be combined to derive error-bars on CSEM data is not obvious. In this study, we use data from the 2009 survey of the Scarborough gas field to demonstrate that (a) a repeat tow may be used to quantify uncertainties from geometry, (b) perturbation analysis also yields a good estimate of data uncertainties as a function of range and frequency so long as the components are added arithmetically rather than in quadrature, and (c) lack of a complex error structure in inversion yields model results which are unrealistic and leads to “over-selling” of the capabilities of CSEM at any particular prospect.

SUMMARY The ability of the marine controlled source electromagnetic method to resolve anisotropy in the sediment conductivity is not very well understood. In this study, we address the resolvability of anisotropy using a Bayesian approach. Two markedly different methods, slice sampling and reversible jump Markov Chain Monte Carlo have been used for the Bayesian inversion of a synthetic model of a resistive oil reservoir trapped beneath the seabed. We use this to identify which components of data can provide the strongest constraints on anisotropy in the overburden, reservoir and underlying sediments.

A modified inversion approach is presented for the effective separation of sources in marine simultaneous shooting acquisition. The method aims to distribute all energy in the simultaneous shot records by reconstructing the individual shot records at their respective locations. The method is applied to a simulated simultaneous long offset data set, where two sources are used to acquire long offsets with conventional cables. In the second example, the performance is investigated on a data set from Western Australia, where two sources where located within close proximity, with only a small cross line distance between them. Results demonstrate that the individual sources can be separated satisfactory for both simultaneous source configurations.

In this case study we present the results from time-lapse analysis on a Wide Azimuth Towed Streamer (WATS) data set from 2010 that was compared to a pre-production Narrow Azimuth Towed Streamer (NATS) data set from 2002 at King / Horn Mountain (KHM) Fields in the Gulf of Mexico. The WATS data set was acquired to improve the overall imaging of the fields and was not acquired for the goal of time-lapse. Nevertheless, we were able to extract a clear time-lapse signal from the WATS survey. The cost of extracting this time-lapse signal was highly reduced compared to a conventional dedicated time-lapse streamer survey acquisition as it only required reprocessing.

Combined processing of these datasets was a technological challenge. The two datasets were co-binned onto a common grid and a common narrow azimuth dataset was extracted. This dataset was analyzed and interpreted and a clear time-lapse signal was observed in the extra-salt areas. The observations in the time-lapse signal were similar to the previously acquired dedicated time-lapse survey from 2005. The noise level from the WATS on NATS time-lapse was higher than from the conventional dedicated time-lapse survey, but the signal was strong enough to be observable above background noise. Observations from this time-lapse project allow us to better understand the production history of the field, lower the risk on some of the infill targets and avoid drilling wells into potential gas caps that may have formed in the fields. The results from this study demonstrate that usable time-lapse observations can be extracted from combining WATS and NATS data at a much reduced cost.

Summary The frontier offshore basins of Angola hold tremendous potential for hydrocarbons in the Pre-Salt section. The Angolan basins have similarities with the Pre-Salt of the Brazilian margin which abutted the Angola offshore area prior to opening of the South Atlantic. Traps were formed during rift phases and include horsts and tilted fault blocks. Depth-migrated dual-sensor streamer seismic improves the imaging of syn-rift structures, which now allows the identification and mapping of prospects in underexplored acreage. Analyses of oils from both sides of the Atlantic indicate similar source rocks, and seismic data show analogous structures.